IEEE Power & Energy Magazine - November/December 2019 - 59

By Erik Ela, Farhad Billimoria,
Kenneth Ragsdale, Sai Moorty, Jon O'Sullivan,
Rob Gramlich, Mark Rothleder, Bruce Rew,
Matti Supponen, and Paul Sotkiewicz
past these modestly high penetration percentages of VRE. We are starting to ask what a market would
look like if the entire energy supply for a particular interval were supplied with 70, 80, 90, or 100%
renewable resources.
European countries, such as Denmark, Ireland, Germany, and Spain, have already seen hours
of 138, 88, 89, and 64% energy supplied by wind and solar power, respectively (with Ireland
being a single interconnection). In the United States, the Electric Reliability Council of Texas
(ERCOT), Southwest Power Pool (SPP), and California Independent System Operator
(CAISO) have seen hours of 56, 66, and 65% energy supplied by wind and solar power,
respectively. CAISO has served 93% of the load from carbon-free resources, and Kansas has served 106% of the load from wind in a single hour. In South Australia, served
by the Australian Electricity Market Operator (AEMO), the amount of energy from
renewables is anticipated to surpass the load by 2020. Asking what, if any, transformational changes to the electricity markets are needed to meet 100% instantaneous renewable levels is not just an academic thought exercise; it is something
for which these market operators need to prepare. If significant market-design
changes are necessary for an economic and reliable system under these scenarios, they may require several transitional steps to get there.
As discussed throughout this issue of the magazine (see the articles by Lew
et al. and Matevosyan et al.), variable renewables, such as wind and solar, have
unique characteristics, and many of these characteristics affect the outcomes
of electricity markets and their potential design evolution. These resources
have variability and uncertainty, creating a greater need for operational flexibility. Compensation must be available so that existing resources have an
incentive to provide flexibility and new or modified ones have an incentive to
build or retrofit with the needed flexibility. As most variable renewables are
nonsynchronous resources, additional incentives may be needed to ensure that
the necessary attributes of synchronous resources are maintained or developed
through other innovative ways. Finally, as wind and solar do not incur a cost to
supply their natural fuel, their expenditures are entirely made up of capital, operations, and maintenance expenses. The majority of market designs across the world
focus on marginal cost pricing and incentivizing for more efficient heat rates and
lower fuel expenses. The greater amount of renewables entering the system can challenge whether incentivizing for these characteristics is still valid.
There are many possible paths electricity markets could take, and there is no simple
answer to the question of which one is best. We have no crystal ball and acknowledge that
a region's market design is driven by stakeholders and regulators. We also do not answer the
question of what a successful market design looks like. This article asks questions about what
may be expected and how markets may be able to address the challenges of high VRE levels. More
research, analysis, and good old trial and error will help the industry understand the potential designs
that may lead to desired outcomes for these scenarios.

Markets Accommodating the Unique Characteristics of VRE
To start the discussion on how the designs of electricity markets may look in the future, it is important
to review some significant changes that have been introduced. In an article written two years ago, many
changes to electricity markets were discussed (Ela et al., 2017), including market expansion and coordination, phase-out of priority dispatch support, new and evolving ancillary service products, designs
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IEEE Power & Energy Magazine - November/December 2019

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